A variety of industrial as well as non-industrial applications use fuel burning boilers which typically operate to convert chemical energy into thermal energy by burning one of various types of fuels, such as coal, gas, oil, waste material, etc. An exemplary use of fuel burning boilers may be in thermal power generators, wherein fuel burning furnaces generate steam from water traveling through a number of pipes and tubes within a boiler, and the generated steam may be then used to operate one or more steam turbines to generate electricity. The electrical or power output of a thermal power generator may be a function of the amount of heat generated in a boiler, wherein the amount of heat may be directly determined by the amount of fuel consumed (e.g., burned) per hour, for example.
A typical steam generating system used in a power plant may include a boiler (known as a Heat Recovery Steam Generator (HRSG) in a combined cycle plant) having a superheater section (having one or more sub-sections) in which steam may be produced and may be then provided to and used within a first, typically high pressure, steam turbine. To increase the efficiency of the system, the steam exiting this first steam turbine may then be reheated in a reheater section of the boiler, which may include one or more subsections, and the reheated steam may be then provided to a second, typically lower pressure steam turbine. However, both the furnace/boiler section of the power system as well as the turbine section of the power system must be controlled in a coordinated manner to produce a desired amount of power.
Moreover, the steam turbines of a power plant are typically run at different operating levels at different times to produce different amounts of electricity or power based on variable energy or load demands provided to the power plant. For example, in many cases, a power plant may be tied into an electrical power distribution network, sometimes called a power grid, and provides a designated amount of power to the power grid. In this case, a power grid manager or control authority typically manages the power grid to keep the voltage levels on the power grid at constant or near-constant levels (that may be within rated levels) and to provide a consistent supply of power based on the current demand for electricity (power) placed on the power grid by power consumers. Of course, the grid manager typically plans for heavier use and thus greater power requirements during certain times of the days than others, and during certain days of the week and year than others, and may run one or more optimization routines to determine the optimal amount and type of power that needs to be generated at any particular time by the various power plants connected to the grid to meet the current or expected overall power demands on the power grid.
As part of this process, the grid manager typically sends power or load demand requirements (also called load demand set points) to each of the power plants supplying power to the power grid, wherein the power demand requirements or load demand set points specify the amount of power that each particular power plant may be tasked to provide onto the power grid at any particular time. Of course, to effect proper control of the power grid, the grid manager may send new load demand set points for the different power plants connected to the power grid at any time, to account for expected and/or unexpected changes in power being supplied to or consumed from the power grid. For example, the grid manager may change the load demand set point for a particular power plant in response to expected or unexpected changes in the demand (which may be typically higher during normal business hours and on weekdays, than at night and on weekends). Likewise, the grid manager may change the load demand set point for a particular power plant in response to an unexpected or expected reduction in the supply of power on the grid, such as that caused by one or more power units at a particular power plant failing unexpectedly or being brought off-line for normal or scheduled maintenance.
While the grid manager may provide or change the load demand set points for particular power plants at any time, steam turbine based power plants themselves cannot generally increase or decrease the amount of power being supplied to the power grid instantaneously, because steam turbine power generation equipment typically exhibits a significant lag in response time (e.g., two to four minutes) due to the physical characteristics of these systems. As is known, response time in this context is the amount of time it takes for the steam generator to reach approximately 66.6 percent of a step change in the demand. For example, to increase the power output of a steam turbine based power generation system, it may be necessary to change the amount of fuel being spent within the system, to thereby increase the steam pressure or temperature of the water within the boiler of the system, all of which takes a finite and non-trivial amount of time. Thus, generally speaking, steam turbine based power plants can only ramp up or ramp down the amount of power being supplied to the grid at a particular and relatively slow rate, which may be based on the specifics of the power generating equipment within the plant.
In an attempt to overcome or reduce this problem, some power plants, generally known as combined cycle power plants, implement both steam turbine power generation equipment and gas turbine power generation equipment. In particular, it is much easier and quicker to alter the power generating capability of gas turbine power generating equipment as the heat flow through the gas turbine is directly related to the quantity of gas burned immediately upstream of the gas turbine. In fact, the response time of most gas turbine power generating equipment is on the order of five to 30 seconds. In any event, in a combined cycle power plant, the gas turbine equipment is operated to ramp up (or down) the load output by the plant in faster manner. Moreover, in a typical combined cycle power plant, the steam turbine is run using steam created by the exhaust of the gas turbines and is primarily producing power from the waste heat of the gas turbine power generating equipment.
However, conventional combined cycle utility plants (i.e., power generating plants) run the steam turbine (ST) equipment with “valves wide open” to minimize throttling losses through the steam turbine control valves. These plants are therefore unable to modulate the steam turbine equipment to provide megawatt (MW) or power regulation. As a result, load control on most combined cycle power plants tend to be open loop systems, in which a change in the unit MW demand is sent directly to the gas turbine controllers without accounting for the potential megawatt change attributed to the steam turbines. The eventual megawatt (power) change on the steam turbine (after the lag time associated with ramping up or down the steam turbine equipment) is then subtracted from the gas turbine demand or control point to achieve the final steady state unit MW power required.
On cycling or ramping power generating units, this method of operation may mean periods of unnecessary gas turbine over or under demand because of the long heat transfer time constants across the heat recovery steam generators (HRSG) within the gas turbine exhaust, and the fact that the steam turbines are in a valves wide open mode and cannot provide load regulation.